Despite a rebuke from a federal appeals court, FERC last week reaffirmed its earlier decision that Pacific Gas and Electric participates voluntarily in CAISO and qualifies for hefty financial incentives to remain in the ISO (ER14-2529-005).
The decision came after the 9th U.S. Circuit Court of Appeals instructed FERC in January 2018 to reassess its longstanding practice of granting an annual 50-basis-point return on equity adder to encourage PG&E to be part of CAISO. The incentive earns the currently bankrupt utility about $30 million a year.
In response to the court’s ruling, FERC instructed PG&E, the California Public Utilities Commission and other interested parties to brief it on the issue of whether PG&E could leave CAISO if it chose. (See Can PG&E Quit CAISO? FERC Wants to Know.)
FERC had concluded in late 2017 that participation in the ISO was voluntary. The commission decided Thursday it had been right all along.
We “find that California law does not mandate PG&E’s participation in CAISO, and that the RTO participation incentive induces PG&E to continue its membership,” FERC wrote. “We therefore reaffirm the commission’s prior grant of PG&E’s request for the RTO participation incentive.”
Mandatory or Voluntary?
The controversy over whether PG&E and other utilities are entitled to the incentive payments has been going on for years.
In the Energy Policy Act of 2005, Congress amended the Federal Power Act to require FERC to provide financial incentives to induce utilities to join RTOs.
FERC responded in 2006 with Order 679, which provided ROE adders for utilities that participate in transmission organizations. The bonuses were meant to give utilities an extra reason to join or remain members of RTOs, which are generally voluntary.
For staying in CAISO, PG&E has requested and received adders under Order 679 since 2007.
The CPUC, however, argued that membership in CAISO is mandatory for the state’s three big investor-owned utilities: PG&E, Southern California Edison and San Diego Gas & Electric. It protested in years past and again in November 2017, saying the adder for PG&E was an “unjustified windfall” at the expense of California ratepayers. The Sacramento Municipal Utility District joined the protest.
FERC dismissed the objections, but on appeal, a three-judge panel of the 9th Circuit ruled FERC commissioners had abused their authority. The commission, the court said, did not reasonably interpret Order 679 as justifying adders for remaining in a transmission organization. Instead, the commission created a generic adder in violation of the order, the judges ruled.
“Order 679 says FERC ‘will approve, when justified, requests for ROE-based incentives for public utilities that join and/or continue to be a member of’ transmission organizations,” the court noted.
“If all utilities that continued to be members of transmission organizations automatically qualified for incentive adders, the ‘when justified’ language would be surplusage,” it said.
FERC Erred, CPUC Argues
On remand from the appeals court, FERC asked the parties to brief it on four issues, including whether California law requires PG&E to participate in CAISO and whether FERC must defer to the CPUC’s interpretation of state law.
PG&E, SCE and SDG&E responded in September and October 2018, supporting PG&E’s contention that participation in CAISO is voluntary and that the incentive adder is justified to encourage them to remain CAISO members.
In addition, PG&E’s participation in CAISO is governed by the Transmission Control Agreement (TCA) between the ISO and transmission owners, whose assets the ISO controls, SCE and SDG&E said in their joint brief. Only FERC has authority over the TCA, they argued.
“The TCA is a filed rate subject to the exclusive jurisdiction of [FERC] and explicitly allows PG&E to withdraw from the CAISO. California lacks jurisdiction to alter the terms of the TCA,” the utilities argued.
The CPUC, the Sacramento Municipal Utility District and the Transmission Agency of Northern California (the “California parties”) filed joint briefs. They argued FERC had misinterpreted the 9th Circuit’s decision, which they said directed FERC to correct its own errors, not to undertake further inquiries.
Moreover, state law governs the dispute, and FERC is obligated to show deference to the CPUC, they contended.
“The California parties respectfully request that the commission conclude that PG&E does not qualify for the transmission organization membership incentive … because the CPUC has demonstrated that PG&E’s continued CAISO membership is not voluntary because it is required by state law,” they wrote.
FERC Decides it was Right
FERC disagreed that the 9th Circuit had only wanted the commission to correct itself.
The “California parties erroneously assume that the 9th Circuit found that California law mandates PG&E’s ongoing participation in CAISO,” it said.
The commission also rejected contentions that state law alone governed the matter.
“As a creature of federal statute created by Congress, this commission’s subject matter jurisdiction over proceedings before it arises solely under the acts that the commission is required to administer,” it said. “Specifically, the issue here involves the transmission and sale at wholesale of electric energy in interstate commerce, over which the FPA provides exclusive jurisdiction to this commission.”
Finally, FERC said PG&E and was free to leave CAISO. No California law prevented it from doing so, FERC concluded, and PG&E could reclaim control of its transmission grid from the ISO without CPUC approval.
“As the commission explained in Order No. 679, the basis for the RTO participation incentive is a recognition of the benefits that flow from RTO/ISO membership and the fact continuing membership is generally voluntary,” FERC wrote.
“In light of the voluntary nature of RTO/ISO membership from the commission’s perspective and the lack of any relevant mandate under California law, we find that PG&E could unilaterally leave CAISO without obtaining CPUC authorization,” FERC said. “Consequently, we find that the RTO participation incentive induces PG&E to remain a participating member of CAISO … [and] we reaffirm the continuation of PG&E’s 50-basis-point ROE adder.”
The transmission trade group WIRES praised the ruling, saying it “clearly complies with the congressional mandate for FERC to provide incentives for public utilities for their participation in RTOs and ISOs.”
Texas regulators last week postponed action on improvements to ERCOT’s day-ahead market (DAM), citing potential delays to implementing the real-time co-optimization (RTC) of energy and ancillary services (48540).
PUC adviser Stephen Journeay
During the Texas Public Utility Commission’s open meeting Thursday, PUC Chair DeAnn Walker said she had met with ERCOT staff earlier in the week. Walker said she was told that incorporating DAM improvements along with RTC would cause a two-year delay in the latter’s implementation.
“ERCOT told me there would be a delay in opening the hood,” Walker said. “Fixing [the DAM] at the same time doesn’t fit in there. I’d rather have them focusing on real-time co-optimization than coming up with a solution on this.”
Walker said delaying day-ahead improvements would give ERCOT’s market participants and the Independent Market Monitor time to determine how they want to move forward.
“This is not anywhere close to being thought through,” she said. “I think they can do this in the regular stakeholder process.”
Rate Case Recovery Remanded Back
The commission remanded back to docket management Southwestern Electric Power Co.’s request to recover $3.9 million in rate case expenses, asking the parties involved to seek a settlement (47141).
Walker told fellow Commissioners Arthur D’Andrea and Shelly Botkin she has long been concerned with the methods used by utilities to recover rate case expenses.
“We would be approving ratepayer expenses that have nothing to do [with the case]. To me, they seem to be the cost of doing business,” Walker said. “The goal by utilities is to recover every single penny over a period of time. If that’s the goal, then we have to start seriously looking at the risks involved when setting their [returns on equity].”
From left to right: PUC Commissioners Shelly Botkin, Chairman DeAnn Walker and Arthur D’Andrea
Commission staff, SWEPCO, the municipal group Cities Advocating Reasonable Deregulation (CARD), the Office of Public Utility Counsel and Texas Industrial Energy Consumers had reached a settlement over rate case expenses incurred through June 30, 2018, in dockets 46449 and 48233.
The commission’s remand asked the parties to reach an agreement that will “fully and finally resolve all issues concerning SWEPCO and CARD’s rate case expenses.” If they are unable to do so, they will request that the case be sent to the State Office of Administrative Hearings for a hearing.
SWEPCO, Entergy Get TCRF Approvals
The PUC approved transmission-cost recovery factor (TCRF) modifications for SWEPCO (49042) and Entergy Texas (49057). The changes will result in TCRF annual revenue requirements of $11.5 million for SWEPCO and $2.7 million for Entergy.
PHILADELPHIA — PJM’s anticipated increase in renewables over the next decade won’t succeed without the support of more reliable fossil fuels and nuclear reactors, industry analysts said last week.
The predictions came during presentations at the Mid-Atlantic Renewable Energy Summit hosted at The Bellevue Hotel on Thursday, where experts from all corners of the energy sector gathered to discuss the future of PJM’s resource mix and the anticipated shift from policy-based investment to more economic drivers.
“The increase we’ve seen so far is nothing compared to the increase that looks like it’s coming at us in the future,” said Stu Bresler, PJM’s senior vice president of markets and planning. “We ain’t seen nothing yet.”
Data from the National Renewable Energy Laboratory and U.S. Energy Information Administration show PJM’s installed wind and solar capacity currently exceeds 11,000 MW — the majority of which joined the grid during the last 10 years. ICF Resources said 70% of the renewables scheduled for connection through 2030 will come online in New Jersey, Maryland and D.C., where elected officials have set aggressive clean energy targets and other policies to reduce the effects of climate change.
The Garden State alone will install 3,500 MW of offshore wind power over the next decade. It announced last month that Denmark-based Ørsted will construct the first 1,100 MW 15 miles off the coast of Atlantic City beginning in the early 2020s. (See Ørsted Wins Record Offshore Wind Bid in NJ.)
“We are living amidst a revolution right now, a revolution in terms of technology change, a revolution of climate change … and finally a revolution of electricity decarbonization,” said Stuart Caplan, partner at Troutman Sanders. “Beware of what you ask for … treat fossil fuels not as an enemy of renewables. The pendulums can swing quickly.”
Caplan said that the intermittency of current renewable technologies means fossil fuels will continue to have a place in PJM in order to “preserve balance.” In March, the Independent Market Monitor said natural gas-fired energy output exceeded coal in PJM’s market last year for the first time ever. (See Monitor Says PJM’s Capacity Market not Competitive.) Economists on Thursday said coal retirements in favor of more efficient combined cycle units will continue — but the cheap price will not, providing a valuable opening for nuclear energy in the market.
D.C. Public Service Commissioner Greer Gillis said reaching the district’s goal of 100% renewable energy and 50% carbon emissions reduction by 2032 will be challenging, but possible. D.C. set the targets in December 2018, making it the most ambitious clean energy policy enacted nationwide, she said.
“We are very optimistic,” she said. “But I think one thing we are all concerned about is the pricing.”
Judah Rose, executive director of energy markets for ICF, said zero-emission credits and renewable energy credits will likely increase between 2022 and 2025, temporarily spiking energy costs. Post 2025, he said, the combination of carbon pricing and states meeting their renewable portfolio standard mandates will cause renewable energy prices to fall.
ICF’s market forecast assumes the implementation of a national CO2 program with a price of $4/ton, though Rose said the “real action” could happen through the Regional Greenhouse Gas Initiative, where policy in the participating states could create “big upward pressure” on the price of carbon. It wouldn’t wipe out gas development entirely, however.
“We still see huge economics for combined cycle units … mostly located in western PJM,” he said. “For coal and nuclear, we see unfavorable economics for both areas. In the long run, however, as gas prices increase and we have some kind of carbon price, we see nuclear becoming economic.”
New Jersey and Illinois have already enacted ZEC programs for their own nuclear plants, despite criticism that the subsidies distort prices in the wholesale electricity market. Ohio legislators also appear close to consensus on a bill to rescue FirstEnergy Solutions’ reactors at Davis-Besse and Perry nuclear plants near Lake Erie. (See Ohio Senate Clears Nuke Rescue.) Supporters of the programs argue PJM’s existing market structure doesn’t value the carbon-free reliability of nuclear energy and that allowing the units to retire would not only be irreversible, but foolish.
“Nuclear has to be part of the equation,” said Jason Barker, director of wholesale market development for Exelon. “If you take just the carbon output in one year of those three [retiring nuclear] units, it’s equal to all of the wind that’s ever been installed in PJM. It’s undeniable in the short run if we want to reach our societal targets.”
Exelon manages the largest nuclear fleet in the country, including the remaining operating reactor at Three Mile Island near Harrisburg, Pa. The company said in June it will deactivate the unit in September after state legislators stalled on a plan to keep it running via ratepayer subsidies and changes to Pennsylvania’s RPS. (See Nuclear Subsidies Still on the Table in Pennsylvania.)
“Because of the intermittency of current dominating renewables, we need something to pick up when the wind stops blowing and the sun stops shining,” Barker said. “We need to value the flexibility attributes of those units, and that will be what drives LMP.”
“So, if there were border adjustments … it would increase the energy value and therefore decrease the cost of the ZEC, therefore making the MOPR less destructive,” Barker said. “Depending on what this MOPR ruling looks like … the carbon pricing could be a substitute or a type of substitute in the absence of more global policy.”
LOS ANGELES — To open his presentation at Infocast’s California Energy Summit last week, Marty Niles, a veteran lineman and founder of Cantega Technologies, played a clip from the quiz show “Jeopardy!”
The deputy director of the National Security Agency said the No. 1 threat to the U.S. electrical grid came from these climbing rodents, host Alex Trebek said.
“What are squirrels?” a contestant answered correctly.
Niles, whose company makes Greenjacket covers for electrical equipment, then showed a series photos and videos in which birds and animals had become trapped in substations, transformers and conductors, sparking fires and explosions. Greenjacket’s covers could help prevent fires caused by animal damage, Niles said.
“We’re just another tool in the toolbox with regard to the fire suppression effort,” he said.
Niles’ presentation was one of several talks at this year’s summit that focused on the utility-sparked wildfires that have ravaged California in recent years. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)
In a panel on wildfire prevention, panelists discussed the need for microgrids to maintain essential services — such as emergency shelters at schools — during incidents in which the main power supply was switched off or damaged.
Craig Lewis, executive director of the nonprofit Clean Coalition, said smaller-scale grids powered by renewable energy are essential, with California facing greater threats from massive fires fueled by climate change.
In the fire-prone Santa Barbara area, he said, electric infrastructure is crucial for pumping water uphill from coastal areas to battle mountain blazes.
“That water is absolutely critical for fighting fires,” he said.
Tim Hade, co-founder and COO of Scale Microgrid Solutions, said California is “on the path to having the most expensive and least reliable electricity in the United States” because of the wildfire threat.
Utilities have been using public safety power shutoffs to prevent their equipment from sparking fires during periods of low humidity and high winds.
With power shut off to entire communities, having microgrids as backup is crucial, Hade and others said. Those who depend on medical devices, for instance, can’t go without electricity.
“We need to reinvent electricity,” Hade said. “That’s the challenge.”
On the same panel, Sumeet Singh, vice president of Pacific Gas and Electric’s community wildfire safety program, said the bankrupt company has been making strides to head off wildfires before they start.
The company is widely blamed for causing the Camp Fire, which burned much of the town of Paradise in November, killing 85 people. PG&E equipment also sparked devastating wildfires in Northern California’s wine country in 2017 and in the Sierra Nevada foothills in 2015, the California Department of Forestry and Fire Protection has said.
The company recently issued a press release outlining the accomplishments of the program Singh heads. They included visual inspections of 96% of about 50,000 transmission structures in high fire-risk areas, the utility said. The company also said it had inspected 222 substations and nearly all its 700,000 distribution poles in high-risk fire areas.
PG&E has installed 430 weather stations since 2018, including 231 so far this year, it said.
In Paradise, PG&E is undergrounding new power lines where it makes most sense, Singh said. It’s also replacing wooden poles with composite structures. During the fast-moving Camp Fire, wooden poles toppled, blocking escape routes for some who died.
“I wish we could say undergrounding is a panacea,” Singh said. But it’s costly and time consuming, and while 1 mile of conductor is being undergrounded, many other miles of line remain at risk.
Another panelist, Diane Moss, founder and director of the Renewables 100 Policy Institute, said her friends from Germany were amazed to see overhead power lines in California that “reminded them of Africa.” Germany undergrounded most of its lines after World War II, she said.
“Are we going to have to wait to do that?” Moss asked.
Abe Powell, chairman of the Montecito Fire Protection District Board, said he understood undergrounding 200 miles of line in Paradise would cost about $1 billion. Montecito, near Santa Barbara, was ravaged by the Thomas Fire in late 2017 and ensuing mudslides in early 2018. The death toll was 23. Southern California Edison has admitted at least partial responsibility. (See Edison Takes Partial Blame for Wildfire in Earnings Call.)
Powell, however, questioned whether undergrounding lines for one community is the best use of $1 billion.
“We haven’t thought this through all the way,” he said.
WASHINGTON — FERC on Thursday adopted two new rules intended to reduce paperwork for electricity sellers with market-based rate authority (MBRA), acting on a proposal issued more than three years ago (Order 860, RM16-17).
Currently, sellers are required to describe the activities of all their upstream owners, often requiring them to submit multiple amendments to their filings. Once the new rule goes into effect on Oct. 1, 2020, sellers will only need to identify their “ultimate” upstream affiliate — the furthest upstream owner.
Sellers will also no longer be required to report assets — such as generators and long-term power purchase agreements — owned by its affiliates with MBRA. They will also no longer have to submit corporate organizational charts. They will, however, be required to report assets owned by affiliates without MBRA, as these are relevant to the seller’s market power analysis, the commission said.
FERC will collect all seller information through a relational database to be created by the order.
“The relational database construct modernizes the commission’s data collection processes, eliminates duplications and renders information collected through its market-based rate program usable and accessible for the commission,” FERC said.
Types of market-based rate authority filings | FERC
Connected Entity Info Tossed
Under the proposal, sellers would have had to identify all affiliate owners with franchised service areas or MBRA, or that directly own or control generation; transmission; intrastate natural gas transportation, storage or distribution facilities; coal supply sources; or access to transportation of coal supplies.
Collectively known as connected entity information (CEI), this new class of information was panned by market participants in late 2015 and again in response to FERC’s proposed 2016 revision. (See FERC Issues Revised Connected Entity, Data Collection Proposal.)
Speakers at a 2015 technical conference and commenters on the proposal said it would create significant reporting burdens.
On Thursday, FERC declined to adopt the CEI provision, instead opening a new docket (AD19-17) “should the commission wish to consider this again in the future,” staff said.
This move was strongly criticized by Commissioner Richard Glick, who issued a partial dissent. “I’m really having a hard time figuring out how that’s any different from killing the proposal altogether, and that’s what I’m very much troubled by,” he said at the commission’s open meeting Thursday.
“In my opinion, through its actions today, the commission is dropping the ball to the detriment of consumers across the country,” he continued. He called CEI “critical” to preventing market manipulation and the exercise of market power. “What I want to know is, why was this information no longer considered to be necessary, or [do] we simply no longer care about how we’re addressing market manipulation?”
FERC also dropped the proposed requirement that traders of financial transmission rights and virtual products also submit affiliate information, which Glick also criticized.
“Virtual/FTR participants are very active in RTO/ISO markets, and surveilling their activity for potentially manipulative acts consumes a significant share of the Office of Enforcement’s time and resources,” Glick said in his dissent. “It may, therefore, be surprising that the commission collects only limited information about virtual/FTR participants and often cannot paint a complete picture of their relationships with other market participants.”
“Without the connected entity reporting requirements contemplated in the [proposal], the commission lacks any effective means of tracking individuals who perpetrate a manipulative scheme at one entity and then move locations and engage in similar conduct elsewhere, as Corteggiano is alleged to have done,” Glick said. “That makes no sense. We should not be leaving the Office of Enforcement to play ‘whack-a-mole,’ addressing recidivist fraudsters only when evidence of their latest fraud comes to light.”
“I know that there are some who will construe our decision not to move forward with the connected entities proposal as a lack of commitment to our Enforcement program,” Chairman Neil Chatterjee said before Glick spoke at the meeting. “To anyone with that misconception, let me be clear: Robust enforcement of our orders and regulations is and will remain one of the commission’s most critical objectives.”
Speaking to reporters after the meeting, Chatterjee said, “I respect Commissioner Glick, but I disagree with the point that he made. I think it’s a matter of good governance. We were ready to move forward with a piece of it; we weren’t ready on the connected entities part, so rather than hold up the MBR piece, which has been out there for three years, we moved forward with it.” He also said he didn’t think “it was a fair characterization” to say that opening the new docket ends the process.
The order is “a critical step in our ongoing efforts to modernize and, where possible, streamline the MBR program to ensure that we have the information we need to evaluate market power while not unduly burdening market participants,” Commissioner Cheryl LaFleur said. “I recognize that these reforms do not address all the issues the connected entities proposal would have covered, particularly with respect to financial market participants and traders. I made the pragmatic decision that it was important to move forward on the MBR improvements that have been held up for three years due to being placed in the same [proposal] as the connected entities.”
Commissioner Bernard McNamee did not participate in the ruling.
Screens Eliminated for 4 RTOs
FERC also approved eliminating the requirement for power sellers with MBRA to submit pivotal supplier and wholesale market share screens in PJM, ISO-NE, MISO and NYISO (Order 861, RM19-2). FERC will now presume that the grid operators’ commission-approved monitoring and mitigation rules provide adequate protection against market power abuse.
MBR sellers of capacity in SPP and CAISO, which do not have capacity markets, will still need to submit the screens. The order’s relief also does not apply to any participants in CAISO’s Energy Imbalance Market.
Effective 60 days after its publication in the Federal Register, the order’s relief would begin with MBR sellers scheduled to file their triennial updates for the Northeast region in December 2019 and June 2020, commission staff said.
Sellers filed almost 600 indicative screens over the last three years, according to staff. Once the rule goes into effect, sellers would be relieved of submitting more than half of those screens, they said.
FERC clarified certain details about its initial proposal, issued last December, but it did not decline to adopt or alter any of its provisions. (See FERC Proposes Market Screen Exemptions.) Though paired with RM16-17 for discussion at Thursday’s open meeting, it received little mention in comparison.
Rehearing Denied on Interlocking Directors
In a third ruling, the commission denied rehearing but made one clarification on its February order updating its regulations on commission authorization of interlocking positions between public utilities and financial companies. (Order 856-A, RM18-15-001). The revised rule provides an exemption for some applicants for interlocking positions between utilities and companies that underwrite public utility securities. (See “Other Rules,” ‘Boring Good’ Rulemaking Seeks to Clean up Order 845.)
The commission denied El Paso Electric’s rehearing request that FERC grant equal treatment to all interlocks authorized under section 45 of its regulations.
“The commission has recognized a difference between holding interlocks among two or more commonly owned or controlled public utilities, and holding an interlock between, for example, a public utility and an electrical equipment supplier,” FERC said. “Interlocks that fall under section 45.2 and are not between two or more commonly owned or controlled public utilities (and therefore are outside the scope of section 45.9a) are reviewed by the commission so that the commission can be sure that the ‘evils to be eliminated by the enactment of [Federal Power Act] Section 305b’ are not present. By contrast, for interlocks that fall under section 45.9a’s automatic authorization, the commission has found that the evils to be eliminated by the enactment of Federal Power Act Section 305b are not present because the potential for abuse would be unlikely to result from such interlocks.”
The commission did grant a clarification on another question raised by EPE, saying that “if, as a result of the change in FPA Section 305b(2) in 1999 and the corresponding changes to section 45.2 of the commission’s regulations made by Order No. 856, an individual no longer holds an interlock that requires commission authorization, that individual no longer needs to adhere to the requirements of [sections] 45 and 46 of the commission’s regulations governing commission approval of such interlocks.”
STOWE, Vt. — Mary Bimonte of Eversource Energy on July 16 presented a joint meeting of the New England Power Pool Reliability and Transmission committees with an overview of the regional network service (RNS) rates that became effective June 1.
Bimonte, a member of the Participating Transmission Owners Administrative Committee, showed the RNS rate increased $1.51/kW-year from last year to $111.94/kW-year, with the region’s aggregate annual transmission revenue requirement (ATRR) rising $41.3 million to nearly $2.19 billion.
Eversource subsidiaries Public Service Company of New Hampshire, NSTAR West and NSTAR East accounted for much of the ATRR increase, along with Vermont Transco and Maine Electric Power.
During a presentation of the five-year RNS rate forecast, Bimonte noted this year’s increase was 67 cents/kW-year short of projections made last year for 2019.
A summary of the RNS five-year forecast from 2020 to 2023 | ISO-NE
Modifying Interconnection Procedures
ISO-NE Director of Transmission Strategy and Services Al McBride led a discussion of proposed modifications to interconnection procedures — specifically, Planning Procedure No. 10 sections 7.7 and 7.8 — to clarify adjustments to interconnection capability following partial market exits.
According to the RTO’s market procedures, “permanent and retirement delist bids can be submitted for all or just a portion of a resource’s capacity. A partial delist bid allows a resource to remove the portion of its megawatts it cannot deliver from all ISO-NE markets or only the capacity market, depending on the type of delist bid submitted.”
“When a partial retirement delist bid clears in the Forward Capacity Auction, the resource remains active and its interconnection rights are reduced to the appropriate megawatt level,” according to the RTO. “When a partial permanent delist bid clears in the FCA, the qualified capacity value for the resource is reduced.”
In February, the NEPOOL Participants Committee approved the general changes, which include methodologies to update the levels of interconnection service available for generators (and external elective transmission upgrades) after the clearing of a retirement delist bid, permanent delist bid or substitution auction demand bid in the Forward Capacity Market.
The RC and TC will alternately discuss the specific proposed revisions ahead of a planned vote by the PC in November, with a tentative effective date of January 2020.
During the previous discussions, stakeholders identified circumstances where the winter capability of their generating facilities after a partial market exit may not be correctly calculated by the formulas currently contained in PP10, McBride said.
The RTO will propose a new section of the Tariff to capture the rules associated with the establishment and relinquishment of interconnection service amounts and plans to present the proposed revisions at the Aug. 21 TC meeting.
Operating Procedure Revisions
The RC voted to recommend that the PC support revisions to a handful of ISO-NE operating procedures slated to become effective Aug. 2, including:
Altering OP-24 to describe the confidential Appendix C as a list of transmission facilities for which transmission owners are required to report protection settings, characteristics, failures or degradation. RTO staffer Jerry Elliott presented proposed revisions reflecting that Appendix C previously included a diagram, but now includes a list. The proposed changes to OP-24 are conforming changes.
Revising OP–12 (Voltage and Reactive Control) and OP-12D (Voltage Schedule Annual Transmittal Form) to clarify local control center actions for providing voltage schedules to generators.
Revising OP-5 (Resource Maintenance and Outage Scheduling) to indicate that outage requests for import capacity resources are for notification purposes only. The motion passed with six opposed (two from the Generation Sector, two from the Supplier Sector and two from the Alternative Resource Sector) and three abstentions (one Generation Sector, one Supplier Sector and one Alternative Resource Sector).
Future Vote on OP-14E Revision
Elliott presented proposed revisions to OP-14E to incorporate energy storage as a type of asset-related demand that can be selected on ISO-NE’s form NX-12E.
The RC is scheduled to vote on the revisions at its Aug. 20 meeting, and the RTO is seeking a vote by the PC at its Sept. 13 meeting.
The changes include correcting terms defined in section I.2.2 of the Tariff or ISO-NE manuals, in addition to replacing the term “nominated consumption level” with the defined term “nominated consumption limit.”
The RTO also notified the RC of revisions to OP-10 Appendix A to update the contact information for the U.S. Department of Energy in cases of reporting major system disturbance, outage or incident. The revisions took effect immediately upon the notification.
Reactive Capability Auditing Tariff Changes
The RC voted to recommend PC support for proposed revisions to section I.2.2 of the Tariff to incorporate definitions for interconnection reliability operating limit (IROL) and system operating limit (SOL).
ISO-NE lead operations analyst Kory Haag said the revisions incorporate four new defined terms in the Tariff: reactive capability audit, reactive resource, IROL and SOL.
The meeting focused on IROL and SOL, which will now be defined as the meaning specified in the glossary of terms used in NERC reliability standards.
NERC defines IROL as “a system operating limit that, if violated, could lead to instability, uncontrolled separation or cascading outages that adversely impact the reliability of the bulk electric system.”
It defines SOL as “the value … that satisfies the most limiting of the prescribed operating criteria for a specified system configuration to ensure operation within acceptable reliability criteria.”
The RC requested an Oct. 1 effective date for the definitions, following a vote by the PC in August.
Eversource Substation Upgrades
The RC voted to recommend that ISO-NE determine that three proposed substation upgrades by Eversource would not adversely affect the stability, reliability or operating characteristics of nearby transmission facilities.
Eversource crews work to restore power following a Jan. 20 ice storm in Connecticut. | Eversource Energy
Upgrades to the Andrew Square and Dewar Street substations in South Boston would entail the installation of two independent current differential high-speed protection groups on the K Street-to-Andrew Square 115-kV cables and the Dewar 115-kV cables to provide the selectivity to differentiate between a line fault and a transformer fault. The work will provide protection system fault clearing selectivity and design in compliance with Northeast Power Coordinating Council protection system design criteria (NPCC Directory 4 BPS). The proposed in-service date for both projects is in November 2019.
An upgrade to the Portsmouth substation in New Hampshire would entail the replacement of an existing 115/34-kV, 44.8-MVA transformer with a 62.5-MVA rated unit, the addition of a second 115/34-kV, 62.5-MVA transformer, installation of one new 115-kV bus tie circuit breaker, and installation of two new 115-kV circuit breaker disconnect switches. Eversource will also install one new 11-kV circuit switcher for high-side transformer protection and add two 7.2-MVAR capacitor banks, one on each 34-kV bus. The upgrade also will add a 34.5-kV bus tie circuit breaker, which will normally be open, with an automatic close function upon loss of a transformer. The proposed in-service date is June 1, 2020.
4 20-MW Solar Projects by FPS Approved
The RC voted to recommend that ISO-NE determine that implementation of four separate 20-MW solar projects proposed by Freepoint Commodities (FPS) would not adversely affect the grid.
None of the projects include energy storage, and each comprises 10 2-MW arrays.
Solar panels in Vermont like the 20-MW projects approved by the NEPOOL RC on July 16 | Green Mountain Power
SGC Engineering’s Jeff Fenn presented the separate project overviews, showing the solar farm in Plainfield, Conn., interconnecting to the 23-kV bus at the Fry Brook substation and with a proposed in-service date of December 2022.
The firm’s project in Fair Haven, Vt., will interconnect to the 46-kV line between the Green Mountain Power Fair Haven and Carver Falls substations, while the project in Shaftsbury, Vt., will interconnect to the 46-kV line between the GMP South Shaftsbury tap and East Arlington substation, both with a proposed in-service date of July 1, 2022. The project in Claremont, N.H., has the same in-service date.
Enhancing Competitive Tx RFP
ISO-NE Transmission Planning Director Brent Oberlin led a discussion of competitive transmission solicitation enhancements that included proposed clarifications to Attachment K of section II of the Tariff, the draft selected qualified transmission project sponsor (SQTPS) agreement, and to sections I.2.2 and I.3.9 of the Tariff associated with preparing for competitive transmission solicitations under FERC Order 1000.
Based on the results of the 2028 Boston Needs Assessment, which were presented to the ISO-NE Planning Advisory Committee in April, the RTO plans to issue its first request for proposals for a competitively developed transmission solution in December 2019. (See ISO-NE Planning Advisory Committee Briefs: April 25, 2019.)
Tx Cost Allocation Revisions
The RC voted to recommend that ISO-NE approve pool-supported costs for two projects by Avangrid’s United Illuminating subsidiary in Connecticut, including $11.24 million for work associated with the East Shore 345-kV circuit switcher replacement and $8.17 million to replace line optical ground wire and related fiber optic equipment on the 115-kV 1130 Line between the Pequonnock and Sasco Creek substations.
UIL determined that none of the costs associated with either upgrade can be considered localized.
Capacity Cost Compensation
The RC voted to recommend that ISO-NE designate PSEG Power’s Bridgeport Harbor gas-fired plant and the Wheelabrator North Andover waste-to-energy plant as dynamic reactive resources meeting the RTO’s capacity cost compensation program eligibility requirements.
The committee recommended the facilities be eligible for compensation associated with a qualified reactive resource designation effective Aug. 1.
RC Consent Agenda
The RC approved a consent agenda that included seven proposed plan application (PPA) notifications for Massachusetts solar generation totaling nearly 27.5 MW.
The list includes five projects being interconnected through Eversource:
Borrego Solar’s 3.75-MW project in Plymouth, interconnecting to the Valley substation, with a proposed in-service date of Dec. 31.
Borrego’s 4.999-MW project in Freetown, interconnecting to the Bell Rock substation, with a proposed in-service date of May 1, 2020.
CVE North America’s 2.5-MW/1.262-MW Wing Lane solar and battery project in Acushnet, interconnecting to the Wing Lane substation with a proposed in-service date of Oct. 31.
SunRaise Development’s 2.5-MW Cranberry Highway project in Wareham, interconnecting to the Tremont substation with a proposed in-service date of Dec. 1.
Syncarpha’s 4.99-MW Chester Road solar and battery project in Blandford, interconnecting to the Blandford substation with a proposed in-service date of Nov. 18.
Two projects will interconnect through New England Power:
Ameresco’s 2.5-MW Otter River Road project in Gardner, interconnecting to the Crystal Lake Substation with a proposed in-service date of Sept. 1, 2020.
NSTAR Electric’s 4.99-MW Denslow Road project in East Longmeadow, interconnecting to the East Longmeadow substation with a proposed in-service date of Nov. 15, 2020.
The consent agenda also included one PPA non-solar notification, the 1.5-MW Madison Business Park battery energy storage facility in Madison, Maine, which New England Battery Storage will interconnect to the Jones Street substation with a proposed in-service date of Jan. 1, 2020.
The agenda also included three Level I (for information only) transmission PPA notifications:
New England Power is updating the summer normal and revised winter line ratings to reflect current cable design on a new 345-kV underground line from the Wakefield Junction substation to the company’s border with Eversource at the Wakefield/Stoneham, Mass., town line; two new circuit breakers at the Wakefield Junction substation; and a new 345-kV variable shunt reactor. The proposed in-service date is in May 2021.
Eversource is updating the summer normal and revised winter line ratings to reflect current cable design on the installation of a new 8-mile, 345-kV underground cable circuit from the Woburn substation in Massachusetts to National Grid’s Wakefield Junction substation, in Wakefield, including 160-MVAR variable shunt reactors at each terminal. The work will expand the 345-kV switchyard at Woburn to be a breaker-and-a-half substation with four bays. The proposed in-service date is in May 2021.
Eversource is also rebuilding the existing 69-kV 667 Line from the Salisbury substation in Salisbury, Conn., to the Falls Village substation because of asset conditions. The proposed in-service date is Dec. 31.
PJM is lagging other regions in addressing carbon emissions and has added significantly more fossil generation than any other grid operator in the U.S. In a recent analysis, we argued that PJM’s market design plays an important role in the build-out of fossil-fueled power plants, and market reform is needed for the cleaner energy future that states and customers in the RTO demand.
Steve Huntoon’s response (See Counterflow: Scary Wrong.) is a collection of distractions from our central concern: PJM’s gas boom will break the “carbon budget” for the region, making it impossible to reach emissions goals. Market structures are a significant factor in determining the energy mix and investments made in a region. PJM’s capacity market, in particular, is built around the characteristics of fossil-fired plants, procures too much capacity and blunts market signals that could drive the expansion of clean energy resources such as wind and solar.
Gas Won’t Save Us
Huntoon suggests that coal-to-gas switching must continue. This is not a climate solution for the region: Retiring coal must be replaced with zero-emission energy sources. Simply replacing remaining coal with gas will not extend the emission reductions PJM has achieved in the past decade. Even as coal-fired power continued to decline last year, carbon pollution in the region (and nationwide) increased year over year in 2018 as natural gas consumption and generation reached new highs. This is projected to continue in the U.S. government’s own most recent energy outlooks. (See the Energy Information Administration’s 2019 Annual Energy Outlook.) Even as coal retires across PJM, emissions in the region will plateau in the coming years under a business-as-usual, high-natural-gas scenario.
| Historical data from S&P Global Market Intelligence; Projections derived from U.S. EIA’s Annual Energy Outlook 2019
This is not a climate-safe future. While the reductions PJM has achieved so far from coal-to-gas switching are roughly consistent with a 1.5 or 2-degree Celsius warming trajectory, they will not continue without focused efforts to deploy zero-carbon resources.
PJM’s market has worked well for gas but poorly for other technologies. A new formula is needed to push the region past gas and achieve reductions in line with a net-zero future.
PJM’s Capacity Market is Flawed
Many factors influence a region’s energy mix, including market rules, as well as state policies and renewable resource potential (i.e. how strong the winds are or how often and powerful the sun shines). We agree with Huntoon that other RTOs, like ERCOT in Texas, were dealt a better hand to play than PJM when it comes to renewable resource quality. Even so, it is clear that PJM’s capacity market design over-procures fossil capacity and blunts clean energy investment.
As we explained in our article, PJM is procuring vastly more capacity than reliability regulators have deemed necessary to keep the lights on.
| PJM Base Residual Auction & Reserve Requirement Study Reports
One reason for this is that PJM has failed to implement a seasonal market and thereby fails to fully leverage resources like demand response, solar and wind. Aggregation fails to address the real issue that the region has different needs in summer and winter.
Huntoon contends that prices would be the same in any case, as “there is no free lunch.” But PJM’s current construct essentially forces all customers to buy a heaping dinner portion even at breakfast time, when they aren’t very hungry, and makes it very costly for chefs to include any menu options other than foods that can be served for both meals. The Brattle Group estimated that separate procurement periods would push costs down by roughly $100 million to $600 million per year.
In addressing our point that PJM’s over-procurement has been costly to customers, Huntoon proposes his own free lunch, contending that our simple intuition that buying more stuff costs more money “profoundly misunderstands” the capacity market. His logic on this point is circular. Huntoon explains that if capacity suppliers had offered higher prices (high enough that PJM wouldn’t want to over-procure supply), costs would have been higher.
This is a faulty counterfactual. If PJM were to just procure the capacity necessary to serve a lower reserve margin (and then stop procuring additional “low-cost” capacity that has bid in), the market would actually see lower clearing prices. Our point is not that PJM should switch to a vertical demand curve (which has other downsides), but rather that after procuring significantly more than its target year after year after year, it is clear that PJM has based its demand curve on erroneous inputs and the overall market construct needs to be reassessed.
In Huntoon’s calculation, he assumed supply bid prices were high enough that PJM would not procure beyond the target reserve (red dot). However, if PJM were to just procure the capacity necessary to serve the target reserve margin (and not procure additional “low-cost” capacity), the market would actually see lower clearing prices (green dot).
PJM’s unwillingness to leverage seasonal resources and persistent over-procurement mean more money is gained from the region’s capacity markets, distorting energy and ancillary markets. Unlike in the rest of the country, renewable resources are largely excluded from resource adequacy planning and are left to compete against heavily subsidized fossil fuel plants in energy markets. In contrast to PJM’s capacity market, wind and solar resources compete in the energy and ancillary services markets on equal footing, as those markets are not defined by administrative criteria.
PJM Can Change Course
Fighting climate change will not be easy. Large, integrated, efficient markets are an essential tool in this fight. But those markets must not create barriers to clean resources or climate policy. Critically, those markets must not be dominated by administrative constructs where incumbent market participants fight over hidden subsidies and create barriers to competition.
Highlighting the consequences of overbuilding gas does not ignore that the region has not been blessed with the same renewable resources as other areas of the country. PJM’s rules play an important role in determining the future resource mix. The recent leadership change at PJM provides the grid operator with an ideal opportunity to shift course, allowing them to better respond to the demands of customers and states, reverse its trend of capacity over-procurement, and better integrating state clean energy policies into a reliable and clean energy future for the region.
Miles Farmer is a senior attorney and Amanda Levin is a policy analyst in the Climate & Clean Energy Program of the Natural Resources Defense Council.
INDIANAPOLIS — State regulators in the MISO and SPP footprints are considering an independent analysis of the interregional planning process to supplement the seams coordination analysis already underway by the two RTOs’ market monitors.
The Organization of MISO States and the SPP Regional State Committee’s Seams Liaison Committee agreed unanimously at a July 21 meeting to scope an independent analysis that would examine whether the RTOs are leaving efficiencies and benefits on the table in their interregional transmission planning.
The joint committee will allot 30 days for stakeholder suggestions on how the analysis might look and what questions it will probe.
“We don’t know at this juncture what the analysis will be,” OMS President and Missouri Public Service Commissioner Daniel Hall told fellow regulators.
The regulators’ plans reflect frustration over the inability of the RTOs to find beneficial projects across their seams.
Missouri PSC economist Adam McKinnie said recently approved improvements to the MISO-SPP interregional planning process may or may not lead to their first-ever project. He agreed with other regulators that interregional project construction is not necessarily an indicator of the health of the MISO-SPP planning process.
“If there’s a good opportunity and a project, let’s do it, but I don’t want to add work. I don’t want to dig ditches for fun,” McKinnie said.
“If there are [economic] benefits and we’re not capturing them with projects, then we have a problem,” Arkansas Public Service Commissioner Ted Thomas added.
MISO and SPP completed two 18-month studies beginning in 2014 and 2016. They began another Coordinated System Plan earlier this year, skipping a 2018 start date in favor of trying to improve their interregional planning processes. However, early indications are that the newest study may not yield a project either. (See “Revised Seams Study with MISO yet to Bear Fruit,” SPP Seams Steering Committee Briefs: July 10, 2019.) The RTOs will report conclusive CSP results at an Aug. 19 Interregional Planning Stakeholder Advisory Committee meeting.
McKinnie said MISO and SPP’s regional economic planning models still differ on assumptions like load, fuel mix and where new resources will be sited.
FERC Commissioner Cheryl LaFleur, who attended the meeting, reminded liaison committee members that MISO and PJM’s level of seams coordination was not always held up as the standard it is now.
“There were six stormy years — maybe not all of them stormy — that it took to get there,” LaFleur said.
LaFleur also said she was working during her short time left on the commission to get her colleagues to devote attention to MISO-SPP seams issues.
Meanwhile, work continues on MISO and SPP’s market monitors’ seams study. Hall said both SPP and MISO market monitors are still open to modifications to the study’s work plan. (See RSC, OMS Approve Monitors’ Seams Study.)
MISO is paying Potomac Economics $250,000 to complete the first phase of the study. SPP has an in-house Market Monitoring Unit and has not disclosed a special budget item.
“We’re ready to go; we’re ready to work with you; and we think it’s time,” Hall said of the study in remarks before the MISO Board of Directors in June.
OMS and the RSC expect the first phase of the monitors’ study results to be released in September. The first phase of the study focuses on market-to-market coordination, rate pancaking and joint dispatch. A second phase of the study will concentrate on interface pricing, interchange optimization and regional directional transfer limits.
NYISO’s effort to price carbon into its wholesale markets could help New York achieve its ambitious clean energy goals, but the policy would benefit from a boost in the social cost of carbon (SCC) or additional programs, according to a study released Tuesday.
The study by the nonprofit Resources for the Future (RFF) indicates a $63/ton carbon price could drive clean energy penetration to as high as 64% of the state’s resource mix by 2025, “well on the way” to the 70% requirement for 2030. The SCC is currently estimated at $40/ton.
The target of 70% renewable generation by 2030 implies an increase in the share of non-emitting generation from its current level of approximately 60% (46% not including Indian Point, which is slated to retire in 2021) to roughly 88% in 2030 (for load-serving entities under the jurisdiction of the New York Public Service Commission) and 100% by 2040, according to the study.
| Resources for the Future
“This analysis suggests pricing carbon within New York electricity markets could help to advance the adoption of clean energy, but a higher carbon price, additional companion policies or different policies will likely be necessary to hit the clean energy goals New York state has set for 2030.”
The think tank used its own Engineering, Economic and Environmental Electricity Simulation Tool (E4ST) to model the impact of carbon pricing on emissions and prices in New York and throughout the Eastern Interconnection based on expectations for 2025.
The study, “Benefits and Costs of Power Plant Carbon Emissions Pricing in New York,” was co-authored by RFF’s Daniel Shawhan and incorporates key assumption changes from an earlier version of the analysis presented last September to the Integrating Public Policy Task Force (IPPTF), a joint effort between the ISO and the PSC. (See ‘Negative Leakage’ fromNY Carbon Charge, Study Shows.)
The ISO’s Market Issues Working Group (MIWG) took over in January from the task force, which over nearly a year and a half had developed the carbon pricing proposal released last December.
“The most influential change was that we used what I consider to be better projections of the costs of solar and wind technology,” Shawhan told RTO Insider.
“The ones we used before were from the [U.S. Energy Information Administration’s] Annual Energy Outlook, and they’re just simply out of date,” Shawhan said. “So we used better assumptions … the medium cost projections from the National Renewable Energy Laboratory annual technology baseline. The effect of that change was to lower the projected cost of solar and wind, and, as a result, we get considerably more emissions reductions and we get a low projected cost to electricity users, lower than some of our prior projections.”
Key changes in assumptions from RFF’s September 2018 analysis of the proposed carbon pricing policy presented to the IPPTF | Resources for the Future
Clean Energy Legislation
NYISO market participants have been debating how the state’s newly enacted Climate Leadership and Community Protection Act (A8429) and its mandated influx of renewables would affect the effort to price carbon. (See “New Energy Law Could Affect CO2 Market Design,” NYISO Business Issues Committee Briefs: June 20, 2019.)
Along with the 70-by-2030 renewables target, the new law nearly quadruples the state’s offshore wind energy goal to 9 GW by 2035 and requires the economy to be carbon-neutral by 2040. It also doubles the distributed solar generation goal to 6 GW by 2025 and targets deploying 3 GW of energy storage by 2030.
Gov. Andrew Cuomo signed the bill July 18, the same day he announced the state was awarding a combined total of 1,700 MW in offshore wind contracts to Equinor’s Empire Wind project and to Sunrise Wind, a joint venture of Ørsted and Eversource Energy.
In addition, the state Department of Environmental Conservation is revising its Clean Air Act regulations to lower allowable NOx emissions from simple cycle and regenerative combustion turbines during the ozone season, effective May 1, 2023, with generator compliance plans due by March 2, 2020. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)
According to the RFF simulation results, New York electricity users in in 2025 would pay the equivalent of between 0.1 and 1.1% of the retail electricity rate for the carbon adder, while the net benefit to society as of that year would be between $108 million and $691 million per year, in 2013 dollars.
Effects of policy on welfare originating in New York. RFF defines “End-User Benefits” as “direct pocketbook and profit effects.” The environmental benefits shown here are from the reduction of New York emissions. The reduction in government revenue is primarily from reduced RGGI allowance prices (low case) and RGGI allowance sales (both cases). | Resources for the Future
The analysis found a carbon adder drives New York renewable energy credit and zero-emission credit prices to zero, incentivizing renewables investment and the maintenance of upstate nuclear generation in the energy markets. It also found the carbon policy increases zonal average wholesale electricity prices in New York by $20 to $24, but with revenue rebated to end users, and other charges reduced, the average cost to end users is 9 cents to $1.21/MWh.
In addition, the study found the Regional Greenhouse Gas Initiative’s Emissions Containment Reserve, due to be introduced in 2021, will provide a mechanism for reducing the emissions cap if the RGGI allowance price falls to the reserve trigger price, resulting in lower total power sector emissions from the RGGI states taken together.
Ohio legislators approved a controversial bill Tuesday to subsidize FirstEnergy Solutions’ nuclear reactors on Lake Erie, making it the third state to provide a financial lifeline to the nuclear industry in PJM.
The Ohio House of Representatives voted 51-38 in favor of the $170 million Ohio Clean Air Act (HB 6). Republican Gov. Mike DeWine quickly signed the bill later that day, officially curtailing the state’s current renewable portfolio standards and tacking on monthly fees — ranging from 80 cents for residential customers to $2,400 for large industrial plants — to electricity bills for the Davis-Besse and Perry nuclear facilities. Some $20 million of the fees collected will support six solar power projects in rural areas of the state.
Ratepayers will also notice a $1.50 charge to supplement two Ohio Valley Electric Corp. (OVEC) coal plants — a House-crafted addition meant to attract support from electric distribution utilities, according to some critics. (See Ohio Nuke Bill: A Worthwhile Tradeoff?)
Davis-Besse Nuclear Power Plant
“We are very pleased that Gov. Mike DeWine signed HB 6 following its successful bipartisan passage in the General Assembly,” said John W. Judge, CEO of FirstEnergy Solutions. “We’re also thankful for the support and commitment by Speaker [Larry] Householder and Senate President [Larry] Obhof, who understood the importance of protecting 90% of the state’s zero-emissions electricity, substantial employment and the need to provide affordable rates from a diverse portfolio of generation sources for Ohioans.”
Judge confirmed that FES will rescind deactivation orders for both plants and prepare for necessary refueling in the spring.
With DeWine’s signature, Ohio joins New Jersey and Illinois as the only states in PJM to subsidize nuclear generation — a policy reaction to the economic impact of cheap, natural gas-fired generation setting prices in the wholesale markets. Supporters insist the support is justified because the RTO’s market structure doesn’t appropriately value the reliability and carbon-free emissions provided by nuclear power. Without them, proponents say states can’t achieve aggressive clean energy targets because renewables are intermittent. (See Nuclear, Gas Seen as Crucial to PJM’s Renewables Growth.)
Gregory Wetstone, CEO of the American Council on Renewable Energy (ACORE), characterized the plan as a “bailout” — echoing the sentiments of critics in both the clean energy and natural gas sectors who argue the subsidies will distort the wholesale energy market and spike electricity prices.
“At a time when the nation is accelerating its transition to affordable, pollution-free renewable power, this legislation goes in precisely the wrong direction with a bailout of aging and uneconomic coal and nuclear plants and a weakening of the state’s renewable portfolio standard,” he said.
“House Bill 6 is just the latest, though maybe the worst, of the retreats from the legislature’s brave stand for utility consumers through power plant competition in 1999,” said Bruce Weston, counsel for the Ohio Consumers’ Counsel (OCC). “Power companies have too much influence in Ohio, and that should be reformed.”
AARP joined ACORE, the OCC and the Ohio Manufacturers’ Association in calling on the governor to veto the bill, to no avail.
Todd Snitchler, CEO of the Electric Power Supply Association, said the bill “unfairly punishes competitive generators who are the largest power producers in Ohio. This bailout jeopardizes competitors’ investments and risks local tax revenues and jobs in the communities hosting competitive coal and natural gas plants that generate thousands of megawatts for Ohio and the PJM region.
“Passage of yet another nuclear bailout makes it more urgent than ever for the Federal Energy Regulatory Commission to swiftly implement effective measures to protect the integrity of PJM’s energy and capacity markets,” he added.
The House vote came six days after the Senate approved the bill, capping off months of hearings that debated the merits of saving the plants at the expense of RPS goals. (See Ohio Senate Clears Nuke Rescue.) Householder (R) had reportedly worked behind the scenes to secure bipartisan support in his chamber by pushing the fees for OVEC, and slashing the RPS mandates long unpopular among state Republicans.
“We are reducing consumers’ bills, repealing wasteful government mandates and keeping good-paying jobs here in Ohio,” Householder said Tuesday. “This is legislation that makes sense for the ratepayers of Ohio.”
Under the plan, the nuclear charges would sunset in 2027, and the Public Utilities Commission would audit the facilities each year between 2022 and 2026 to determine if the subsidies are still needed — an attempt to placate critics who insist the plants aren’t losing money at all.
The RPS — the law determining how much electricity electric distribution utilities procure from renewable resources — will drop from 12.5% by 2027 to 8.5% until 2025, with no continuation of the mandate thereafter.
Opponents have vowed to seek a referendum opposing the bill on the November 2020 election ballot. ClearView Energy Partners said opponents have 90 days after July 23 to collect the necessary 265,774 signatures needed to get it on the ballot. The success of such a measure depends largely on the way election officials word the referendum, ClearView said.
